Well production by fluid lifting

ABSTRACT

Oil production from formerly producing wells may be restored without removing a preexisting production tube by perforating the production tube above the tubing packer and charging the casing annulus at the surface with a pressurized charging fluid fluid, preferably deoxygenated air, that is lighter than water. The pressurized charging of the casing annulus with charging fluid is continued to purge the production tube flow bore of a static water column and reduce the tubing column head pressure against the formation production zone.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to methods and apparatus for enhancing the extractive flow of crude petroleum from production wells.

2. Description of Related Art

When a petroleum extraction well is first completed, in situ formation pressure is often sufficient to drive the formation fluid (crude oil) to the surface. Over time, with the continued extraction of the in situ fluid, the original formation pressure declines to the point of insufficient internal energy to drive a flow of fluid to the surface. This circumstance is exacerbated by the frequent invasion of water and other contaminating fluids into the formation interstices vacated by the original formation fluid. These contaminating fluids ultimately find their way into the production flow stream and into the well production tube. Due to a greater specific gravity of water than oil, the well production tube slowly fills with water to prevent all fluid extraction flow.

Unfortunately, natural production flow cessation may occur before even half of the in situ petroleum is drained. By some geological theories, the “depleted” fields of the world still contain at least as much petroleum as was originally extracted.

If the affected well is sufficiently shallow and sufficiently perpendicular to the earth's center, fluid production of a well originally produced by natural drive force may be continued by pumping. In such cases, the original production tube is withdrawn from the well and replaced by a sucker rod assembly. Sucker rod assemblies are mechanical lifts comprising a reciprocating rod disposed coaxially within a specialized production tube. The reciprocating rod supports a plurality of annular piston elements having opposite faces linked by pressure differentially operated check valves. The upper or surface end of the reciprocation rod is mechanically manipulated in a reciprocating motion to lift the formation fluid to the surface along the rod tube in successive increments. As with most reciprocating machines, sucker rod assemblies are expensive to position and to maintain.

Production inducements for deviated well bores and extremely deep wells are more difficult. In some of these examples, production has been enhanced by a process known to the art as “gas lifting”. Gas lifting includes the step of positioning a specialized formation fluid production tube within the well having one or more gas—lift valves strategically positioned along the length of the tube. The open, lower end of the production tube extends into the formation production zone. The well casing annulus between the external tubing wall and the internal casing wall at a point above the production zone is sealed by a packer to isolate the well production zone from the casing annulus above the zone.

The gas-lift valves are essentially pressure differentially controlled valves that link the internal flow bore of the fluid production tube with the external annulus volume between the production tube exterior and the well casing interior. A non-oxidizing gas such as methane, natural gas, or cryogenic nitrogen is charged under pressure into the casing annulus. When the designated pressure differential between the casing annulus and the tubing flow bore is attained, the lift valve opens to admit the gas into the flow bore. The higher pressure gas entrains the non-flowing fluid in the tubing flow bore with liquid displacing bubbles that enlarge as they rise to the surface of the production tube. This rising bubble expansion pushes the previously static flow bore fluid up and out of the tube at the surface. Additionally, the gas bubble entrainment reduces the density of the standing fluid column thereby reducing the positive, bottomhole head pressure that has prevented production flow in the first place. Fresh formation fluid is allowed to drain into the production zone of the well and into the production tube flow bore.

This process is continued with a continuing injection of gas into the well casing annulus at the wellhead. As the fluid pressure gradient within the tubing flow bore declines, additional lift valves open down the length of the production tube to further reduce the formation zone pressure until a net flow of new formation fluid is produced at the surface end of the production tube.

Although operationally effective, in many cases the process is economically marginal or negative due to the cost of the gas to drive the process. If low cost natural gas is available, the process may be profitable. If not, compressed methane or cryogenic nitrogen is the usual alternative. Production by means of the alternative gases is rarely profitable.

It is, therefore, an object of the present invention to teach a more economical process for fluid lifting the production of crude oil from a well.

It is also and object of the present invention to disclose a combination of well production equipment that economically facilitates the practice of the present invention process.

Another object of the present invention is to teach a method of opening the flow of a shut-in well without removing a pre-positioned production tube.

SUMMARY OF THE INVENTION

These and other objects of the invention are accomplished by one preferred embodiment in which a pre-positioned production tube is wire-line or slick-line perforated at a point above the production zone packer and, preferably, below or proximate of an oil-water interface standing in the production tube flow bore. A suitable fluid having a density less than water such as gaseous nitrogen, oxygen depleted air (non-cryogenic nitrogen) or carbon dioxide is charged into the well casing annulus above the production zone packer.

Pressure of the charging fluid bears against the surface of any fluid standing the casing annulus to force it into the tubing flow bore through the perforations. Initially, the pressure induced casing fluid flow will translate in both directions, up and down the tubing bore. However, the tubing down-flow capacity is limited. Hence, the flow is forced upward and out of the tubing flow bore at the surface. Continued charging expunges all of the static overburden fluid from the tubing and replaces it with a fluid that is lighter than water.

With the overburden fluid removed from the tubing flow bore, the overburden fluid being replaced by the lighter charging fluid, the charging fluid pressure may, in some cases, be reduced to permit a flow resumption of formation fluid into the production zone and up the production tube.

Another preferred embodiment of the invention also includes wire-line or slick-line perforation of the pre-existing production tube at a point above the tubing bottom packer. Internally of the tubing flow bore, a wire-line set tubing stop is positioned below the perforation. The landing nipple of a jet pump is positioned within the tubing stop to project a flow bore opening below the tubing stop. The outside surface (OD) of the jet pump upper end is sealed to the inside wall of the tubing flow bore by a top hold-down packer. The nozzle inlet orifices for the jet pump driving fluid flow are positioned within an annulus volume between the outside surface of the jet pump and the inside wall surface of the production tube. This annulus volume is axially delineated between the top hold-down packer and the bottom tubing stop.

As with the first embodiment of the invention, charging fluid enters the casing annulus at or near the wellhead to bear against the standing fluid surface thereby driving any standing annulus fluid through the preset tubing perforations and into the aspirator nozzle inlets. Discharge of fluid flow from the nozzle is channeled through an aspirator orifice to induce a low pressure zone within the jet pump body upstream of the orifice. This low pressure zone is flow line linked with the well production zone thereby inducing a formation fluid drainage into the jet pump landing nipple and up the production tube.

A third embodiment of the invention entails one or more gas-lift valves in side-pocket mandrels. These side pocket mandrels are flow carrier increments in production tubing string. Below the bottom-most gas-lift valve but above tubing packer a jet pump sub is positioned in the mandrel tubing string.

As charging gas sequentially opens the gas-lift valves starting from the top and advancing downwardly, the overburden fluid is removed up the tubing string. As the tubing flow bore back-pressure declines due to fluid extraction above the open lift valve, the open valve closes and the next lower valve opens.

This sequence continues until all lift valves have opened and closed. Only the jet pump remains open to continue aspirating the production zone.

BRIEF DESCRIPTION OF THE DRAWINGS

Relative to the drawings wherein like reference characters designate like or similar elements throughout the several figures of the drawings:

FIG. 1 is a typical prior art well schematic shown in axial cross section;

FIG. 2 is an axial cross-section representing the first embodiment of the invention;

FIG. 3 is an axial cross-section representing the second embodiment of the invention;

FIG. 4 is sectioned detail of the jet pump section of the second embodiment;

FIG. 5 is an elevation view of jet pump sub embodiment of the invention

FIG. 6 is a schematic view of the invention embodiment that combines a gas-lift valve in the jet pump tubing string.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The environment of utility for the present invention is generally represented by FIG. 1 as a Prior Art schematic of an oil well. The well comprises a raw borehole 12 drilled through the earth formations 10 into a productive formation 13. In many cases, a casing pipe 14 is extended along the borehole for a predetermined portion of the borehole depth and secured in place by an annular collar of cement 16.

At a depth corresponding with the production formation 13, the casing 14 and cement 16, if present, is perforated by numerous apertures and fissures 18. The perforations 18 facilitate the drainage flow of formation fluid into a production zone 20 within the casing interior.

Often, the borehole 12 continues past the production formation. In these circumstances, the borehole 12, or if cased 14, may be obstructed with a plug packer 22 secured below the production zone 20.

A well with sufficient pressure in the production formation 13 to drive the drainage fluid to the surface may be produced through the open flow bore of a production tube 24. The O.D. surface of the bottomhole end of the production tube 24 is sealed to the interior wall face of the casing 14 or borehole wall by means of a tubing packer 26. The open end 25 of the production tube flow bore below the packer 26 extends into the well production zone 28. Although the inflow end 25 of the production tube 24 flow bore is graphically represented here by FIG. 1 as an axially biased cross-cut, in normal practice, however, the inflow end of a production tube is a screened opening into the interior production tube flow bore.

As the production formation 13 is drained of in situ petroleum, water may seep into the formation to fill the formation interstices vacated by the extracted petroleum. Such migrant water also finds its way into production zone flow and up the production tube 24. Over time and continued production, the oil/water ratio of the production tube flow stream decreases with a consequent increase in the tubing flow column density. Eventually, the standing fluid head within the column exerts a bottomhole pressure that equals the in situ formation pressure. At that point the production flow at the surface stops and the fluid column within the production tube 24 is static.

Standing statically in the tubing flow bore, fluids of different specific weights will separate, more or less, into respective strata. For example, the top or upper strata 30, being the less dense fluid, may be predominately oil. Below the oil is a heavier water column 32. Although described herein by the term “water”, the aqueous well bore fluid usually comprises a mixture of water, acid and emulsified petroleum. The two immiscible fluid columns meet at a contiguous interface 34. Although the originally mixed fluids separate in the tubing column, the total head pressure above the production zone 20 remains the same; substantially equal to the in situ formation pressure.

Depending on the integrity of the packer 26 and/or the continuity of the casing 14 wall, a column of water 36 may also accumulate in the borehole or casing annulus 15.

In a first embodiment of the invention, represented by FIG. 2, for example, restoration of productive flow from a “depleted” well includes the preparatory step of securing an injection flow connection 42 proximate of the wellhead 40 for injecting pressurized charging fluid into the casing annulus 15. The charging fluid is preferably oxygen depleted air such as non-cryogenic nitrogen. However, other non oxidizing fluids such as natural gas, methane, carbon dioxide may also be suitable depending on the well site economics.

Further to the charging fluid connection, 42, the preexisting production tube 24 is in situ perforated at a strategic point 44 above the packer 26. Usually, in situ production tube perforations are executed by a “slick line” or wire-line operation that includes a small diameter perforating gun suspended from the surface at the end of a wire-line. The depth of tubing perforation is selected to sufficiently reduce the tubing column overburden pressure sufficient to restore production flow.

Compressed charging fluid 50 enters the well casing annulus 15 through the injection flow connection 42 to bear upon the surface 38 of any fluid column that may be standing in the annulus. With the surface discharge end 46 of the tubing 24 flow bore open into a discharge zone, annulus fluid is driven through the perforations 44. There being no volumetric accommodation for flow displacement downwardly, the top pressure driven annulus fluid escapes up the tubing flow bore pushing the static fluid column in the tubing flow bore ahead and out of the tube at the surface.

When the surface 38 of the annulus fluid column 36 is driven below the tubing perforations 44, the remaining fluid column in the tubing flow bore begins entrainment by the lighter charging fluid. As the rising charging fluid displaces the flow bore liquid from the surface discharge zone 46 of the tube, the overburden pressure on the production zone begins to decline. At this point, residual in situ formation pressure begins to push additional formation fluid into the production zone 20 and up the tubing 24 flow bore where it joins the charging fluid mixture zone proximate of the perforations 44.

Usually, the resumed flow of formation fluid comprises the same mixture of oil and water that originally terminated the well production. Consequently, it is frequently necessary to continue injection of the charging fluid to sustain the production fluid flow. However, a reduction of the charging fluid flow rate and pressure may be permitted after the original water head is discharged. Moreover, the majority of charging fluid is normally recyclable. Hence, sustained production flow is economically burdened only by the cost of charging fluid compression and loss replenishment.

Except for the charging fluid compression apparatus, which is normally surface positioned and operated, the process includes no dynamic machine elements subject to wear or structural failure.

A second embodiment of the invention is represented by the schematic of FIG. 3 and detail of FIG. 4. As with the first embodiment, a preexisting production tube 24 stands within the casing 14. The tube 24 supports a static head of production fluid that may have gravimetrically separated into lighter and heavier liquid elements. The production tube O.D. is sealed to the casing l.D. wall by means of a packer 26.

This FIG. 3 invention embodiment also includes in situ perforations 44 of the preexisting tubing. Additionally, however, a tubing stop 52 is secured, for example, by wire-line manipulation to the l.D. wall of the tubing 24 below the perforations 44 as best illustrated by FIG. 4. The jet pump assembly 55 includes a landing nipple 54 that is seated within an axial aperture of the tubing stop 52. The upper end of the jet pump 55 is aligned and secured by a top hold-down packer 56 that is strategically positioned above the tubing apertures 44. This alignment of elements creates an aspirator nozzle supply plenum 58 around the jet pump 55 linked by the tube perforation apertures 44 to the casing annulus 15. The nozzle supply plenum 58 serves as a fluid supply reservoir for charging fluid flow into the aspirator nozzle inlet orifice 62.

Operationally, the second invention embodiment is similar to the first embodiment in that the charging fluid is channeled into the casing annulus 15 via an injection flow fitting 42 to pressure load a standing fluid column 36 in the casing annulus 15. Casing annulus fluid 36 is displaced under the pressure load through the tubing apertures 44 into the nozzle supply plenum 58. From the nozzle supply plenum 58, fluid is driven through the orifice 62 for high velocity jet discharge from the nozzle 60. The high velocity jet discharge is directed through a larger diameter aspirator nozzle 64 to generate a low pressure flow induction zone at the jet pump inlet 66.

Referring to the detail of FIG. 4, attention is directed to the check valve 70 in the nozzle 60. This illustrated embodiment of a check valve comprises a ball 72 caged between a ball valve seat and a gage- pin 74. Fluid flow entering the nozzle inlet 66 lifts the ball 72 off the valve seat. The cage-pin 74 prevents the ball 72 from flowing out of the nozzle flow bore while the drive fluid flows around the valve ball 72.

In the event that natural production flow is restored by removal of the tube 24 overburden fluid, it may be tolerable to eliminate the charging fluid flow. In such a case, the pressure differential between the tubing 24 flow bore and the jet pump secondary annulus 58 would reverse and the check valve ball 72 would pressure differentially seat to close the nozzle bore.

Although the jet pump aspirating principles are effective with a liquid charging fluid discharged from the nozzle 64, the flow induction efficiency is considerably greater when the charging fluid is a compressed gas. When the compressed gas is released into the liquid filled tubing bore, the gas nucleates into numerous small bubbles, each containing a fixed, finite weight of gas. In conformance with Boyle's Law, as the bubbles rise in the tubing flow bore column, the fluid environment pressure declines. As the environment pressure declines, the fixed weight of gas charging fluid in each bubble volumetrically expands to accelerate the displacement of surrounding liquid.

FIGS. 5 and 6 illustrate a third embodiment of the invention that comprises a jet pump sub 80 that is line coupled in a straight tubing string 24 or below a side pocket mandrel tube 82.

The jet pump sub 80 essentially conforms to the jet pump body 55 illustrated by FIG. 4 with the exception that the nozzle inlet 62 is protected by a slotted screen 84, for example.

Unless the original production tube is installed with the jet pump sub 80 in-line, which it may be, it will be necessary to withdraw the tubing 24 to insert the pump sub 80. However, no wire-line or perforating procedures are necessary. The entire casing annulus becomes the charging fluid plenum for the pump sub 80.

In the case of the FIG. 6 embodiment, a gas-lift valve string 28 comprises several lift valves 90, 92 and 94, for example. The valve orifices and mechanisms are disposed in side-pocket mandrel joints 82 above the jet pump 80.

Operatively, the casing annulus 15 is charged with an opening pressure that, for example, may be 2000 psi for a lift-valve at 3000 ft. depth. If the flow bore head pressure is 1500 psi at that point, a 500 psi differential opening pressure may be necessary to open the first lift valve 90.

Once lifting flow begins, the opening pressure differential declines. For example, is valve 94 is at 3500 ft., the internal flow bore head pressure may have declined to 1200 psi and only a 250 psi differential is required to open valve 94. Hence, the casing annulus pressure may be reduced to 1450 psi.

At the same time that valve 94 is opening to 250 psi differential, this differential is insufficient to hold the valve 90 open. Hence, valve 90 closes at the approximate pressure differential that valve 92 opens considering the respective depth i.e. head, differential between valves 90 and 92.

This sequence continues down the tubing string until all lift valves in the string 28 have opened and closed leaving only the jet pump 80 as transferring charging fluid from the casing annulus 15 into the production tube flow bore.

As is often the case with deep, gas drive well, the presence of excess water in the production flow stream may be intermittent. Consequently, the flow bore of a production tube may be purged of a stagnating water head and resume an unassisted production of petroleum for an indeterminate period. Eventually, however, another water flow will invade the production to stagnate the production. Advantageously, the invention embodiment of FIG. 6 may be positioned as the original well completion and continued indefinitely by intermittently purging the flow bore of accumulated water and thereafter stopping the flow of external lifting gas to permit the natural drive production.

As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, “upstream” and “downstream”, “above” and “below” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left-to-right or right-to-left or other relationship as appropriate. Moreover, in this specification and appended claims, the terms “pipe”, “tube”; “tubular”, “casing”, “liner” and/or “other tubular goods” are to be interpreted and defined generically to mean any and all of such elements without limitation of industry usage.

Having fully described the presently known preferred embodiments of our invention, those of skill in the art will understand other obvious permutations and modifications of the invention. As definition of our invention, therefore, 

1. A method of extracting earth formation fluid comprising the steps of: a. drilling a borehole into an earth formation containing formation fluid; b. positioning a production tube within said borehole, said production tube having a flow bore extending from a formation fluid production zone to a surface discharge zone, said flow bore being confined within a surrounding tube wall; c. at a point above said formation fluid production zone, sealing a well annulus between an internal wall within said borehole and an external surface of said tube wall; d. in situ perforating said tube wall above said annulus seal; and, e. delivering a pressurized charging fluid into said well annulus above said tube wall perforations to drive substantially all fluids present in said flow bore up said flow bore into said surface discharge zone.
 2. A method as described by claim 1 wherein said borehole is lined with a casing pipe and said internal wall within said borehole is an internal diameter surface of said casing pipe.
 3. A method as described by claim 1 wherein said tube wall is perforated from within said tube flow bore while positioned within said borehole.
 4. A method as described by claim 1 wherein said borehole is plugged below said fluid production zone.
 5. A method as described by claim 1 wherein said charging fluid is non-cryogenic nitrogen.
 6. A method as described by claim 1 wherein said charging fluid is oxygen depleted air.
 7. A method as described by claim 1 further comprising the steps of: a. positioning a jet pump within said flow bore above said well annulus seal, said jet pump having a fluid flow passage between a suction end and a discharge end, an aspirating nozzle within said flow passage between said suction and discharge ends and a nozzle supply orifice externally of said flow passage between said suction and discharge ends; b. sealing said tube flow bore around said jet pump suction end below said tube wall perforation; c. sealing said tube flow bore around said jet pump discharge end above said tube wall perforation to position said nozzle supply orifice between said jet pump suction and discharge end seals.
 8. A method as described by claim 7 wherein tube flow bore space around said jet pump between said seals respective to said suction and discharge ends provides a fluid supply plenum for said aspirating nozzle.
 9. A method as described by claim 7 wherein at least one gas lift valve is positioned in said production tube above said jet pump.
 10. A method of enhancing the fluid production of a petroleum well having a production tube disposed within a wellbore between a formation fluid production zone and a surface discharge zone, said method comprising the following steps: a. sealing a first cross-sectional zone between and inside surface of said wellbore and an outside surface of said production tube at a point above said production zone; b. in situ perforating said production tube at a point above said first cross-sectional zone; c. positioning a jet pump within a flow bore of said production tube proximate of said production tube perforation, said pump having a housing around a formation fluid flow channel sealed to an internal flow bore of said production tube above and below said tube perforation to provide an aspirating fluid supply plenum between said above and below seals; and, d. supplying aspirating fluid to an annulus space between said inside surface of said wellbore and said outside surface of said production tube above said first cross-sectional zone.
 11. A method of enhancing the fluid production of a petroleum well as described by claim 10 wherein the supply of aspirating fluid opens and closes at least one gas lift valve in said production tube above said jet pump.
 12. A method of enhancing the fluid production of a petroleum well as described by claim 10 wherein a plurality of gas lift valves are sequentially opened and closed prior to aspirating fluid entering said jet pump.
 13. A method of enhancing the fluid production of a petroleum well as described by claim 10 wherein said aspirating fluid is non-cryogenic nitrogen.
 14. A method of enhancing the fluid production of a petroleum well as described by claim 10 wherein said aspirating fluid is oxygen depleted air.
 15. An earthen fluid production well comprising: a borehole penetrating a fluid bearing earth formation; a fluid production tube comprising a tube wall around a tube flow bore, said production tube disposed within said borehole between a fluid production zone proximate of said formation and a fluid discharge zone proximate of the earth's surface; a first fluid flow seal between said tube wall and an internal wall surface within said borehole surrounding said tube wall, said fluid seal disposed above said production zone; perforations of said tube wall above said first fluid flow seal; a jet pump having a housing, said housing having a suction flow end, a discharge flow end and an aspirating fluid inlet orifice in said housing between said suction and discharge flow ends, said jet pump disposed between a second fluid seal of said tube flow bore around said housing proximate of said suction flow end and a third fluid seal of said tube flow bore around said housing proximate of said discharge flow end whereby said fluid inlet orifice is open to borehole space surrounding said tube wall; and, at least one gas lift valve in said production tube above said third fluid seal. 